Diversion acid containing a water-soluble retarding agent and methods of making and using

ABSTRACT

Described herein are aqueous composition(s) containing water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent. Further described are methods of making and using such compositions.

RELATED APPLICATION INFORMATION

This application claims the benefit of U.S. Provisional Application Ser.No. 62/214,047 filed Sep. 3, 2015 and Patent Cooperation TreatyApplication Serial No. PCT/US2016/49553 filed on Aug. 31, 2016, entitled“Diversion Acid Containing a Water-Soluble Retarding Agent and Methodsof Making and Using,” which are both incorporated herein in theirentirety.

FIELD

The disclosure relates to diversion acids containing water-soluble acidretarding agents, and to methods of making and using.

BACKGROUND

This section provides background information to facilitate a betterunderstanding of the various aspects of the disclosure. It should beunderstood that the statements in this section of this document are tobe read in this light, and not as admissions of prior art.

The maintenance and stimulation of oil and gas wells with speciallydesigned fluids is critical to the efficient extraction of theseresources. Well treatment fluids have many roles: hydraulic fracturing,gravel packing, water flooding and acidizing. Acid treatment isconsidered the oldest well stimulation technology, having first beenapplied in 1895. When injected at low rates into carbonate formations,hydrochloric acid (HCl) can form conductive wormholes that extendradially from the well bore. Acids can also be injected intosubterranean formations at rates high enough to cause fracturing. Inthis case, the acid unevenly dissolves the walls of the fracture, sothat when the injection is stopped and the fracture closes, conductivechannels extending the length of the fracture remain.

HCl is very reactive, and at higher temperatures (>200° F.) and/or lowinjection rates favor facial dissolution over wormholing in matrixtreatments. For this reason, less reactive acid formulations werepursued. One approach is to use organic acids such as formic and aceticacid. Organic acids have higher pKa's than HCl, and will not completelyspend in the reservoir. A second approach is to suspend the acid as awater-in-oil emulsion, which restricts aqueous acid contact with thereservoir and thus slows the reaction rate. In recent work, we havedeveloped a method whereby HCl reactivity is attenuated by certain watersoluble compounds to create single-phase retarded acid systems.

During an acid treatment, the highest permeability parts of theformation will accept the largest volumes of acid, thus increasing thepermeability of these high permeability zones even further. Continuedtreatment of these same zones does little to stimulate production inother parts of the reservoir. To redirect acid flow to less permeableparts of the reservoir, diversion fluids are often pumped between acidstages. The diversion fluids are designed to enter the most permeablesections of the formation and create a temporary plug. The followingacid stage will be sent to another part of the formation, and thesestages can iterate to achieve optimal fluid placement.

A variety of materials can serve as diversion agents. Simple compoundssuch as benzoic acid flakes are used to plug the formation very close tothe wellbore, and then dissolve into the natural hydrocarbons as thewell is put into production. Oil-soluble resins also work in thismanner. Other fluids, often containing polymer or surfactants, aredesigned to viscosify in the formation, setting a thick plug that willbreak after the treatment is complete.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In a first aspect of the disclosure, aqueous composition(s) are providedincluding: water; a viscoelastic surfactant; an acid; and awater-soluble acid retarding agent.

In another aspect of the disclosure, methods are provided including a)providing an aqueous composition including: water; a viscoelasticsurfactant; an acid; and a water-soluble acid retarding agent; and b)treating a formation fluidly coupled to a wellbore with an oilfieldtreatment fluid comprising the aqueous composition.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described withreference to the accompanying drawings, wherein like reference numeralsdenote like elements. It should be understood, however, that theaccompanying figures illustrate the various implementations describedherein and are not meant to limit the scope of various technologiesdescribed herein, and:

FIG. 1 depicts an example of equipment used to treat a wellbore and/or aformation fluidly coupled to the wellbore according to some embodimentsof the disclosure;

FIG. 2 shows pore volumes to break through versus interstitial velocitycurves for aqueous acid solutions based upon tests performed at 70° F.,according to the disclosure;

FIG. 3 shows pore volumes to break through versus interstitial velocitycurves for aqueous acid solutions based upon tests performed at 200° F.,according to the disclosure;

FIGS. 4A-4E depict face dissolution of core samples evaluated inaccordance with the disclosure; and,

FIG. 5 shows calcium generation concentration versus time curves forsome aqueous acid solutions evaluated, according to the disclosure.

FIG. 6 shows viscosity versus shear rate for fresh VDA's containingviscoelastic surfactant and HCl with and without MgCl₂.

FIG. 7 shows viscosity versus shear rate for spent VDA's containingviscoelastic surfactant and HCl with and without MgCl₂.

FIG. 8 shows pore volume to breakthrough (PVBT) versus flow rate for aVDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 9 depicts wormhole patterns in the limestone cores after thetreatment with VDA's containing viscoelastic surfactant and HCl with andwithout MgCl₂, and at the same flow rate 0.2 ml/min.

FIG. 10 shows normalized pressure versus pore volume (PV) for a VDAcontaining viscoelastic surfactant and HCl with and without MgCl₂ atflow rate 6 ml/min.

FIG. 11 shows a computer simulated graph of MD (measured depth) versuswormhole radius (at 100 md (millidarcy)/1 md permeability contrast) with0.5 bbl/min total injection rate of a VDA containing viscoelasticsurfactant and HCl with and without MgCl₂.

FIG. 12 shows a computer simulated graph of rate per zone versus time(at 100 md/1 md permeability contrast) with 0.5 bbl/min total injectionrate of a VDA containing viscoelastic surfactant and HCl with andwithout MgCl₂.

FIG. 13 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/1 md permeability contrast) with 1bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 14 shows a computer simulated graph of rate per zone versus time(at 100 md/1 md permeability contrast) with 1 bbl/min total injectionrate of a VDA containing viscoelastic surfactant and HCl with andwithout MgCl₂.

FIG. 15 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/1 md permeability contrast) with 5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 16 shows a computer simulated graph of rate per zone versus time(at 100 md/1 md permeability contrast) with 5 bbl/min total injectionrate of a VDA containing viscoelastic surfactant and HCl with andwithout MgCl₂.

FIG. 17 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/1 md permeability contrast) with 10bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 18 shows a computer simulated graph of rate per zone versus time(at 100 md/1 md permeability contrast) with 10 bbl/min total injectionrate of a VDA containing viscoelastic surfactant and HCl with andwithout MgCl₂.

FIG. 19 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/10 md permeability contrast) with 0.5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 20 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/10 md permeability contrast) with 0.5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 21 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/10 md permeability contrast) with 1bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 22 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/10 md permeability contrast) with 1 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 23 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/10 md permeability contrast) with 5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 24 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/10 md permeability contrast) with 5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 25 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/10 md permeability contrast) with 10bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 26 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/10 md permeability contrast) with 10 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 27 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/20 md permeability contrast) with 0.5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 28 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/20 md permeability contrast) with 0.5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 29 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/20 md permeability contrast) with 1bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 30 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/20 md permeability contrast) with 1 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 31 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/20 md permeability contrast) with 5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 32 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/20 md permeability contrast) with 5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 33 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/20 md permeability contrast) with 10bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 34 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/20 md permeability contrast) with 10 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 35 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/50 md permeability contrast) with 0.5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 36 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/50 md permeability contrast) with 0.5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 37 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/50 md permeability contrast) with 1bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 38 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/50 md permeability contrast) with 1 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 39 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/50 md permeability contrast) with 5bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 40 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/50 md permeability contrast) with 5 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

FIG. 41 shows a computer simulated graph of MD (length of the wellbore)versus wormhole radius (at 100 md/50 md permeability contrast) with 10bbl/min total injection rate of a VDA containing viscoelastic surfactantand HCl with and without MgCl₂.

FIG. 42 shows a computer simulated graph of rate per zone versus time(at 100 md (millidarcy)/50 md permeability contrast) with 10 bbl/mintotal injection rate of a VDA containing viscoelastic surfactant and HClwith and without MgCl₂.

DETAILED DESCRIPTION

The following description of the variations is merely illustrative innature and is in no way intended to limit the scope of the disclosure,its application, or uses. The description and examples are presentedherein solely for the purpose of illustrating the various embodiments ofthe disclosure and should not be construed as a limitation to the scopeand applicability of the disclosure. While the compositions of thepresent disclosure are described herein as comprising certain materials,it should be understood that the composition could optionally comprisetwo or more chemically different materials. In addition, the compositioncan also comprise some components other than the ones already cited. Inthe summary of the disclosure and this detailed description, eachnumerical value should be read once as modified by the term “about”(unless already expressly so modified), and then read again as not somodified unless otherwise indicated in context. Also, in the summary ofthe disclosure and this detailed description, it should be understoodthat a concentration or amount range listed or described as beinguseful, suitable, or the like, is intended that any and everyconcentration or amount within the range, including the end points, isto be considered as having been stated. For example, “a range of from 1to 10” is to be read as indicating each and every possible number alongthe continuum between about 1 and about 10. Thus, even if specific datapoints within the range, or even no data points within the range, areexplicitly identified or refer to only a few specific, it is to beunderstood that inventors appreciate and understand that any and alldata points within the range are to be considered to have beenspecified, and that inventors had possession of the entire range and allpoints within the range.

Unless expressly stated to the contrary, “or” refers to an inclusive orand not to an exclusive or. For example, a condition A or B is satisfiedby anyone of the following: A is true (or present) and B is false (ornot present), A is false (or not present) and B is true (or present),and both A and B are true (or present).

In addition, use of the “a” or “an” are employed to describe elementsand components of the embodiments herein. This is done merely forconvenience and to give a general sense of concepts according to thedisclosure. This description should be read to include one or at leastone and the singular also includes the plural unless otherwise stated.

The terminology and phraseology used herein is for descriptive purposesand should not be construed as limiting in scope. Language such as“including,” “comprising,” “having,” “containing,” or “involving,” andvariations thereof, is intended to be broad and encompass the subjectmatter listed thereafter, equivalents, and additional subject matter notrecited.

Also, as used herein any references to “one embodiment” or “anembodiment” means that a particular element, feature, structure, orcharacteristic described in connection with the embodiment is includedin at least one embodiment. The appearances of the phrase “in oneembodiment” in various places in the specification are not necessarilyreferring to the same embodiment.

The terms “formation” or “subterranean formation” as utilized hereinshould be understood broadly, and are used interchangeably. A formationincludes any underground fluidly porous formation, and can includewithout limitation any oil, gas, condensate, mixed hydrocarbons,paraffin, kerogen, water, and/or CO₂ accepting or providing formations.A formation can be fluidly coupled to a wellbore, which may be aninjector well, a producer well, and/or a fluid storage well. Thewellbore may penetrate the formation vertically, horizontally, in adeviated orientation, or combinations of these. The formation mayinclude any geology, including at least a sandstone, limestone,dolomite, shale, tar sand, and/or unconsolidated formation. The wellboremay be an individual wellbore and/or a part of a set of wellboresdirectionally deviated from a number of close proximity surfacewellbores (e.g. off a pad or rig) or single initiating wellbore thatdivides into multiple wellbores below the surface.

The term “oilfield treatment fluid” as utilized herein should beunderstood broadly. In certain embodiments, an oilfield treatment fluidincludes any fluid having utility in an oilfield type application,including a gas, oil, geothermal, or injector well. In certainembodiments, an oilfield treatment fluid includes any fluid havingutility in any formation or wellbore described herein. In certainembodiments, an oilfield treatment fluid includes a matrix acidizingfluid, a wellbore cleanup fluid, a pickling fluid, a near wellboredamage cleanup fluid, a surfactant treatment fluid, an unviscosifiedfracture fluid (e.g. slick water fracture fluid), and/or any other fluidconsistent with the fluids otherwise described herein. An oilfieldtreatment fluid may include any type of additive known in the art, whichare not listed herein for purposes of clarity of the presentdescription, but which may include at least friction reducers,inhibitors, surfactants and/or wetting agents, fluid diverting agents,particulates, acid retarders (except where otherwise provided herein),organic acids, chelating agents, energizing agents (e.g. CO₂ or N₂), gasgenerating agents, solvents, emulsifying agents, flowback controlagents, resins, breakers, and/or non-polysaccharide based viscosifyingagents.

The term “high pressure pump” as utilized herein should be understoodbroadly. In certain embodiments, a high pressure pump includes apositive displacement pump that provides an oilfield relevant pumpingrate—for example at least 0.5 barrels per minute (bpm), although thespecific example is not limiting. A high pressure pump includes a pumpcapable of pumping fluids at an oilfield relevant pressure, including atleast 500 psi, at least 1,000 psi, at least 2,000 psi, at least 5,000psi, at least 10,000 psi, up to 15,000 psi, and/or at even greaterpressures. Pumps suitable for oilfield cementing, matrix acidizing,and/or hydraulic fracturing treatments are available as high pressurepumps, although other pumps may be utilized.

The term “treatment concentration” as utilized herein should beunderstood broadly. A treatment concentration in the context of an HClconcentration is a final concentration of the fluid before the fluid ispositioned in the wellbore and/or the formation for the treatment, andcan be any concentration necessary to provide sufficient acidicfunction. The treatment concentration may be the mix concentrationavailable from the HCl containing fluid at the wellsite or otherlocation where the fluid is provided from. The treatment concentrationmay be modified by dilution before the treating and/or during thetreating. Additionally, the treatment concentration may be modified bythe provision of additives to the fluid. In certain embodiments, atreatment concentration is determined upstream of additives delivery(e.g. at a blender, hopper, or mixing tub) and the concentration changefrom the addition of the additives is ignored. In certain embodiments,the treatment concentration is a liquid phase or acid phaseconcentration of a portion of the final fluid—for example when the fluidis an energized or emulsified fluid.

Aqueous compositions described below and useful in accordance with thedisclosure exhibit a retarded acid reactivity that facilitates greaterdepth of fracture and/or matrix acidizing. The aqueous composition cancomprise, consist essentially of, or consist of: water; a viscoelasticsurfactant; an acid; and a water-soluble acid retarding agent. The acidcan be selected from the group consisting of hydrochloric acid (HCl),nitric acid, phosphoric acid, sulfuric acid, hydrofluoric acid,hydrobromic acid, perchloric acid, hydrogen iodide, alkanesulfonicacids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylicacids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaricacid, citric acid, tartaric acid, or their derivatives, and mixturesthereof. Generally, an acid is transported to a wellsite. According tosome embodiments, the acid is present in the aqueous compositions in anamount up to about 36 wt %, or from about 7.5 to about 36 wt %, or fromabout 7.5 to about 28 wt %, or from about 7.5 to about 20 wt %, based onthe total weight of the composition. In some other embodiments, acid ispresent in the aqueous compositions in an amount of at least about 37 wt%.

In some embodiments, an acid that has shown particular utility in theaqueous composition according to the disclosure is hydrochloric acid. Insome other embodiments, the aqueous composition may include an amount ofhydrofluoric acid (HF). HF exhibits distinct reactions from HCl, and isuseful in certain applications to enhance the activity of the resultingaqueous solution. For example, HF is utilized in the cleanup ofsandstone formations where HCl alone is not effective for removingcertain types of formation damage. It is believed that the presentaqueous solution will have effects with HF similarly to the observedeffects with HCl. Accordingly, solutions can be formulated with a totalacid amount that is much higher than presently attainable formulations.In yet another embodiment, the HF is present in the aqueous compositionin an amount of at least 0.25% by weight. The HF may be present inaddition to the amount of HCl, and/or as a substitution for an amount ofthe HCl.

Another component of the aqueous compositions useful according to thisdisclosure are water-soluble acid retarding agents (RA), which haveutility in retarding the rate at which the acid solution reacts withcarbonate-mineral, or other surfaces inside the formation. Thus, awater-soluble acid retarding agent may slow the reactivity of the acidtowards the carbonate-mineral surfaces, without compromising its acidcapacity. Such retardation is useful in the context of stimulating orimproving production from subterranean formations that containhydrocarbons, steam, geothermal brines and other valuable materials asknown in the art. Slowing the rate of reaction may allow deeperpenetration of the acid into the subterranean formations than regularacid, thereby increasing the formation permeability and productivity.Water-soluble acid retarding agents, as used herein, includes anymaterial that reduces acid activity through a mechanism other than meredilution. The water-soluble acid retarding agent can comprise acomponent selected from the group consisting of a salt, urea or one ifits derivatives, an alpha-amino acid, a beta-amino acid, a gamma-aminoacid, an alcohol with one to five carbons, a surfactant having astructure in accordance with Formula I or Formula II below, andcombinations thereof.

-   -   in which R₁ is a hydrocarbyl group that may be branched or        straight chained, aromatic, aliphatic or olefinic and contains        from about 1 to about 26 carbon atoms and may include an amine;        R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon        atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon        atoms; and Y is an electron withdrawing group. As an example of        this embodiment, the zwitterionic surfactant has the betaine        structure:

-   -   in which R is a hydrocarbyl group that may be branched or        straight chained, aromatic, aliphatic or olefinic and has from        about 1 to about 26 carbon atoms and may contain an amine;        n=about 2 to about 4; and p=1 to about 5.

The salt can comprise: i) a cation selected from the group consisting oflithium, sodium, potassium, rubidium, cesium, beryllium, magnesium,calcium, strontium, barium, scandium, yttrium, titanium, zirconium,hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten,manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt,rhodium, iridium, nickel, palladium, platinum, copper, silver, gold,zinc, cadmium, mercury, boron, aluminum, gallium, indium, thallium, tin,ammonium, alkylammonium, dialkylammonium, trialkylammonium andtetraalkylammonium, and combinations thereof; and ii) an anion selectedfrom the group consisting of fluoride, chloride, bromide, iodide,sulfate, bisulfate, sulfite, bisulfite nitrate, alkanesulfonates,arylsulfonates, acetate, formate, and combinations thereof. According tothe present embodiments, the retarding agent is added to the aqueouscomposition in an amount up to its solubility limit in the aqueouscomposition. According to some embodiments, the water-soluble acidretarding agent is present in the aqueous composition(s) in an amount ofup to about 40 wt %, or from about 1 to about 40 wt %, or from about 5to about 35 wt %, or from about 5 to about 20 wt %, based on the totalweight of the aqueous composition.

In some embodiments, such as in the presence of urea, the aqueouscomposition may include HCl as the acid in a weight fraction exceeding37%. The retarding agent present in some aqueous compositions useful inaccordance with the disclosure allows the HCl fraction to exceed the 37%normally understood to be the limit of HCl solubility at atmosphericpressure. Such retarding agents include at least one salt compound andurea, or urea derivative. Above 37%, normally, the evolution of HCl gasfrom the solution prevents the HCl fraction from getting any higher. Inone or more embodiments, the HCl weight fraction of the aqueous solutionmay be as high as 45.7 wt %.

Without being bound by any particular theory, inventors envisagemechanisms that inhibit acid activity. The first involves the disruptionof the hydrogen-bonded network of water. In the Grotthuss proton-hoppingmechanism, protons move in water not through Brownian motion, but rathercharge transport through shifting hydrogen bonds. Solutes are known todisrupt the Grotthuss mechanism by interacting with water themselves,rather than allowing protons to associate freely. This slows the protontransport to the wormhole wall during a matrix acidizing treatment. Theintroduction of salt solutes also has a similar second effect by simplyreplacing water. The lack of water molecules crowds the fluid and limitsthe diffusion of protons. The amount of RA present in the compositioncan be any concentration necessary to provide sufficient acidretardation function.

A second mechanism involves the dissociation of acids in solution. Asmentioned, organic acids have higher pK_(a)'s than HCl, making theprotons from these acids less available for reaction. In some aspects ofthe disclosure, compounds that lower the polarizability (as indicated bythe dielectric constant) of water are used, which therefore decrease theproton dissociation of acids. It is believed that aqueous solutes canmodify the activity of acids in water in one or both of thesemechanisms.

A parameter that quantifies the retardation of the acid is theretardation factor. As described herein, the retardation factorindicates the ratio of apparent surface reaction rates. According to thepresent embodiments, the retardation factor of the aqueous compositionis higher or equal to a retardation factor of a second solution of acidof a same concentration as the acid comprised in the aqueous compositionwithout the retarding agent. For example, in various embodiments, theaqueous composition may exhibit an acid retardation factor higher thanor equal to about 3, at least about 5, or at least about 11 at about 70°F. At about 200° F., the composition may exhibit an acid retardationfactor higher than or equal to about 3, higher than or equal to about 5,or even higher than or equal to about 7.

Water is present in the aqueous composition in an amount sufficient todissolve the acid and the retarding agent. According to embodimentsaccording to the disclosure, the water concentration included in theaqueous composition may be greater than 0 wt % and lower or equal to 80wt %. In various embodiments, the water concentration may be lower than60 wt %, or lower than 40 wt % or lower than 20 wt %, and equal to orhigher than 8 wt %, or equal to or higher than 10 wt %. In yet otherembodiments, the water concentration may even be lower than 8 wt %.

According to some embodiments, an amount of water is mixed with aretarding agent, where the amount of water is present in an amountbetween 0.3 and 5 times the mass of the RA, where any lower limit can be0.35, 0.4, or 0.45 and any upper limit can be 1.0, 1.2, 1.25, where anylower limit can be combined with any upper limit. The procedure furtherincludes dissolving an amount of acid into the combined amount of waterand RA. The acid, such as HCl, may be added by any method, such asbubbling HCl gas through the solution. The dissolving of the HCl mayoccur after dissolving of the RA, simultaneous with the dissolving ofthe RA, or at least partially before the dissolving of the RA. Theamount of HCl gas is in a molar ratio of between 4.0 and 0.5 times theamount of the RA. In yet another embodiment, the procedure includesdissolution of at least a portion of the RA in the water during thedissolution of the HCl in the combined water and RA. Example operationsinclude beginning the dissolution of the HCl and adding the RA as asolid or a solution, providing some of the RA in solution with the waterand some of the RA as a solid, and/or providing the RA as a solid in thewater and dissolving the HCl into the water while dissolving the RA.

Viscoelastic surfactants (VES) create aqueous gels that are employed asoil well treatments for hydraulic fracturing, sand migration control anddiversion. U.S. Pat. No. 7,237,608, Fu et al., SELF DIVERTING MATRIXACID filed in the U.S. Patent Office on Oct. 20, 2004, granted Jul. 3,2007 is incorporated herein by reference in its entirety, and disclosesviscoelastic surfactants, among other things, which are useful for theaqueous composition(s) disclosed herein. The viscoelastic surfactant cancomprise a zwitterionic surfactant having a structure in accordance withFormula III or Formula IV below.

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic, or olefinic and contains from about 17 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or analkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbylgroup having from 1 to about 5 carbon atoms; and Y is an electronwithdrawing group. As an example of this embodiment, the zwitterionicsurfactant has the betaine structure:

in which R is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and has from about 17 to about26 carbon atoms and may contain an amine; n=about 2 to about 4; and p=1to about 5.

The viscoelastic surfactant can be erucic amidopropyl dimethyl betaine.According to some embodiments, the viscoelastic surfactant is present inthe aqueous composition(s) in an amount of up to about 6% v/v or fromabout 0.02 to about 6% v/v, or from about 0.04 to about 4% v/v, or fromabout 0.2 to about 3% v/v, based on the total volume of the aqueouscomposition.

The aqueous composition can be in the form of a gel. The aqueouscomposition can have a lower viscosity at a pH below about 0 as comparedto a viscosity of an equivalent aqueous composition which does notcontain the water-soluble acid retarding agent. The aqueous compositioncan have a viscosity, at temperatures between about 70° F. to about 200°F. and a pH above about 3, which is higher than the viscosity of anequivalent aqueous composition which does not contain the water-solubleacid retarding agent.

Further, it is also within the scope of the present disclosure that theaqueous compositions may be combined with one or more other additivesknown to those of skill in the art, such as, but not limited to, otherdiverting agents, such as, but not limited to, acrylamide polymers,fibers, such as polylactic acid, nylon or cellulose, or particulates,such as polylactic acid particulates, sodium chloride particulates orbenzoic acid flakes, corrosion inhibitors, scale inhibitors,demulsifiers, foaming agents, hydrogen sulfide scavengers, reducingagents and/or chelants, and the like. For example, non-surface activesubstituted ammonium containing amino acid derivatives may be used asenvironmentally friendly corrosion inhibitors that effectively protectvarious tools employed in oilfield operations by surface treating thesetools.

The corrosion inhibitor is typically provided in liquid form and ismixed with the other components of the treatment fluid at the surfaceand then introduced into the formation. The corrosion inhibitor systemis present in the treatment fluid in an amount of from about 0.2% toabout 3% by total weight of the treatment fluid. The corrosion inhibitorused with the fluids of the present disclosure includes an alkyl,alkenyl, alycyclic or aromatic substituted aliphatic ketone, whichincludes alkenyl phenones, or an aliphatic or aromatic aldehyde, whichincludes alpha, or beta-unsaturated aldehydes, or a combination ofthese. Alkyl, alycyclic or aromatic phenone and aromatic aldehydecompounds may also be used in certain applications. Other unsaturatedketones or unsaturated aldehydes may also be used. Alkynol phenone,aromatic and acetylenic alcohols and quaternary ammonia compounds, andmixtures of these may be used, as well. These may be dispersed in asuitable solvent, such as an alcohol, and may further include adispersing agent and other additives.

Chelating agents are materials that are employed, among other uses, tocontrol undesirable reactions of metal ions. In oilfield chemicaltreatments, chelating agents are frequently added to matrix stimulationacids to prevent precipitation of solids (metal control) as the acidsspend on the formation being treated. These precipitates include ironhydroxide and iron sulfide. In addition, chelating agents are used ascomponents in many scale removal/prevention formulations. Two differenttypes of chelating agents may be used: polycarboxylic acids (includingaminocarboxylic acids and polyaminopolycarboxylic acids) andphosphonates. The non-surface active substituted ammonium containingaminoacid derivatives may act as chelating agents when present in thetreatment fluid in amount of from about 0.05% to about 10% or from about1 wt % to about 5 wt %, based upon total weight percent of the treatmentfluid.

Some embodiments according to present disclosure are methods fortreating a formation penetrated by a wellbore. The methods involveproviding an oilfield treatment fluid including the aqueous compositionas described herein to a high pressure pump and operating the highpressure pump to treat at least one of a wellbore and the formationfluidly coupled to the wellbore. In an embodiment, the aqueouscomposition is prepared by mixing the acid, the water-soluble acidretarding agent, the viscoelastic surfactant and water present in anamount sufficient to dissolve the other components. The operation of thepump may include at least one of (i) injecting the treatment fluid intothe formation at matrix rates; (ii) injecting the treatment fluid intothe formation at a pressure equal to a pressure that fractures theformation; and (iii) contacting at least one of the wellbore and theformation with the oilfield treatment fluid.

Referring now to FIG. 1 , a system 100 used to treat a wellbore 106and/or a formation 108 fluidly coupled to the wellbore 106 is depicted.The formation 108 may be any type of formation with a bottom holetemperature up to about 204° C. (400° F.). In various embodiments thetemperature is at least 38° C. (100° F.). The temperature may also rangefrom about 38° C. to about 204° C. The wellbore 106 is depicted as avertical, cased and cemented wellbore 106, having perforations providingfluid communication between the formation 108 and the interior of thewellbore 106. However, the particular features of the wellbore 106 arenot limiting, and the example provides an example context 100 for aprocedure.

The system 100 includes a high-pressure pump 104 having a source of theaqueous composition 102, as described herein. The high pressure pump 104is fluidly coupled to the wellbore 106, through high pressure lines 120in the example. The example system 100 includes tubing 126 in thewellbore 106. The tubing 126 is optional and non-limiting. In variousembodiments, the tubing 106 may be omitted, a coiled tubing unit (notshown) may be present, and/or the high pressure pump 104 may be fluidlycoupled to the casing or annulus 128. The tubing or casing may be madeof steel.

Certain additives (not shown) may be added to the aqueous composition102 to provide an oilfield treatment fluid. Additives may be added at ablender (not shown), at a mixing tub of the high pressure pump 104,and/or by any other method. In one or more embodiments, a second fluid110 may be a diluting fluid, and the aqueous composition 102 combinedwith some amount of the second fluid 110 may make up the oilfieldtreatment fluid. The diluting fluid may contain no acid, and/or acid ata lower concentration than the aqueous composition 102. The second fluid110 may additionally include any other materials to be added to theoilfield treatment fluid, including additional amounts of an RA. Incertain embodiments, an additional RA solution 112 is present and may beadded to the aqueous composition 102 during a portion when the aqueouscomposition 102 is being utilized. The additional RA solution 112 mayinclude the same or a different RA from the aqueous composition 102,and/or may include RA at a distinct concentration from the aqueouscomposition.

The high pressure pump 104 can treat the wellbore 106 and/or theformation 108, for example by positioning fluid therein, by injectingthe fluid into the wellbore 106, and/or by injecting the fluid into theformation 108. Example and non-limiting operations include any oilfieldtreatment without limitation. Potential fluid flows include flowing fromthe high-pressure pump 104 into the tubing 126, into the formation 108,and/or into the annulus 128. The fluid may be recirculated out of thewell before entering the formation 108, for example utilizing a backside pump 114. Referring still to FIG. 1 , the annulus 128 is shown influid communication with the tubing 126. In various embodiments, theannulus 128 and the tubing 126 may be isolated (e.g. with a packer).Another example fluid flow includes flowing the oilfield treatment fluidinto the formation at a matrix rate (e.g. a rate at which the formationis able to accept fluid flow through normal porous flow), and/or at arate that produces a pressure exceeding a hydraulic fracturing pressure.The fluid flow into the formation may be either flowed back out of theformation, and/or flushed away from the near wellbore area with a followup fluid. Fluid flowed to the formation may be flowed to a pit orcontainment (not shown), back into a fluid tank, prepared for treatment,and/or managed in any other manner known in the art. Acid remaining inthe returning fluid may be recovered or neutralized.

Another example fluid flow includes the aqueous composition 102including the acid, RA and viscoelastic surfactant. The example fluidflow includes a second aqueous solution 116 including acid andoptionally a RA. The fluid flow includes, sequentially, a first highpressure pump 104 and a second high pressure pump 118 treating theformation 108. As seen in FIG. 1 , the second high-pressure pump 118 isfluidly coupled to the tubing 126 through a second high pressure line122. The fluid delivery arrangement is optional and non-limiting. In oneembodiment, a single pump may deliver both the aqueous solution 102 andthe second aqueous solution 116. In yet another example, either thefirst aqueous solution 102 or the second aqueous solution 116 may bedelivered first, and one or more of the solutions 102, 116 may bedelivered in multiple and alternating stages such that the aqueouscomposition 102 including the acid, RA and viscoelastic surfactantenters the most permeable section(s) of the formation to create atemporary plug, allowing a subsequent stage of the second aqueoussolution 116 including acid and optionally a RA to flow to and penetrateless permeable sections of the formation. The method can alsopotentially include some stages where the solutions 102, 116 are mixed.

The following examples are presented to further illustrate thepreparation and properties of the wellbore fluids of the presentdisclosure and should not be construed to limit the scope of thedisclosure, unless otherwise expressly indicated in the appended claims.

EXAMPLES Example 1

Various formulations were prepared using different retarding agents andHCl as the acid. A series of tests were conducted to evaluate theseformulations. To fully assess the properties of the preparedformulations, the tests were conducted in an autoclave under up to 3000psi hydrostatic pressure, with the thermal energy transmitted through asilicone oil bath. To determine the retardation factor (RF) of certainadditives, formation response tests were conducted with different acidformulations. In the experiments, Indiana limestone cores, which were 1inch in diameter by 6 inches in length, were held at ˜2800 psi confiningpressure to ensure that no fluids channeled around the sides, and wereheated to desired temperature. The acid fluids were flowed through thecore, with a ˜1200 psi back pressure, which were conditions provided sothe acid will preferentially form wormholes. When the wormhole extendedthe entire length of the core, the pressure drops across the coreapproached zero, which was indicative that the fluid was no longerflowing through porous medium, but rather what approximated a tortuouspipe.

The number of pore volumes of fluid required to create the wormholes wasa function of the acid injection velocity (u_(i), FIGS. 2 and 3 ). Theoptimal injection velocity (u_(i-opt)) is that which requires the lowestnumber of pore volumes for the wormhole to break through the core. Usingthis approach, pore volume to break through (PVBT) curves versusinterstitial velocity curves were generated and the u_(i-opt) and RFcalculated for each acid formulation (Table 1) at 70° F. (FIG. 2 ) and200° F. (FIG. 3 ).

TABLE 1 Retardation Factors of Acid Formulations Estimated RetardingAgent retardation Temperature Retarding Agent concentration factor Entry(° F.) Additive (% by weight) (RF) 1 70 none — — 2 urea 18.5 3.3 3N,N′-dimethyl 27 5.8 urea (DMU) 4 MgCl₂ 19 10.9  5 200 none — — 6 urea18.5 1.3 7 MgCl₂ 19 3.1

The estimated retardation factor was calculated according to thefollowing equation:

${RF}_{x} \sim \left( \frac{u_{{i - {opt}},{HCl}}}{u_{{i - {opt}},x}} \right)^{2}$

All aqueous fluids evaluated contained hydrochloric acid (15%weight/volume) and a corrosion inhibitor (0.6% by volume). The resultsdemonstrate that compounds which disrupt the hydrogen bonding network ofwater and its dielectric constant are able to retard the activity ofacid in subterranean formations. In particular, magnesium chloride(MgCl₂) used as a retarding agent showed significant retardation atsimilar or lower concentrations than the other retarding evaluated.

Wormholes in carbonate formations can acquire different structuresdepending on the rate of acid injection. At very low injection rates,there is no wormhole at all, as only the face of the formationdissolves. Wormholes that do form at low injection rates tend to bebroad and conical. Close to the optimum injection rate, a dominant,narrow wormhole forms with a small amount of branching. When theinjection rate is increased past the optimum injection rate, the acid isforced into less permeable zones and creates a ramified (highlybranched) wormhole. Ramified structures will transition to uniformlydissolved rock at very high injection rates. By comparing thecharacteristics of the injection face of the cores from the acidinjection experiment described in evaluations above, estimates of thewormhole characteristics can be made. Table 2 provides the low acidinjection rates, break through times and pore volumes, from theevaluations above at 200° F., and FIGS. 4A-4C graphically illustrate thecore face images and break through characteristics at low acid injectionrates at 200° F. (photographic representations are provided in U.S.Provisional Application Ser. No. 62/154,945, and included herein byincorporation).

TABLE 2 Core face images and break through characteristics at low acidinjection rates at 200° F. Fluid => 15% HCl + 15% HCl + 15% HCl 18.5%urea 19% MgCl₂ Injection rate (ml/min) 0.2 0.3 0.2  Break through time(h:mm) >3:30 >1:30 0:34 Pore volumes to break through >3.4  >3 0.53

In the tests performed at 200° F., the core faces treated with 15% HCl(FIG. 4A) and 15% HCl with urea (FIG. 4B), both showed a large amount ofcore facial dissolution 402 and developing conical wormholes 404. Inboth cases, however, the confining pressure punctured the sleeve holdingthe core because too much of the rock face dissolved. For the 15% HClwith MgCl₂ fluid (FIG. 4C), the entry wormhole was much smaller and thewormholes 406 broke through to the opposite face in a timely fashion, 34minutes with 0.53 pore volumes to break through. These indicate that atlower injection rates, retarded acid with MgCl₂ was effective. Table 3provides the results of the same experiment conducted at 250° F., withsimilar comparative results both in data and facial dissolution as shownin FIG. 4D (for HCl alone) and FIG. 4E (for HCl with MgCl₂). A largeamount of core facial dissolution 402 and a developing conical wormholes404 occurred with HCl alone, while little facial dissolution and anarrower wormhole 406 resulted with the HCl and MgCl₂ mixture.

TABLE 3 Core break through characteristics at low acid injection ratesat 250° F. Fluid => 15% HCl 15% HCl + 19% MgCl₂ Injection rate (ml/min)0.4 0.4  Break through time (h:mm) >2:05 0:13 Pore volumes to breakthrough >4 0.34

Example 2

In another example, rotating disk experiments were performed tocharacterize the relative surface reaction rates of acidic solutions.The experiment was conducted by spinning a marble or limestone disk, atambient temperature and 1250 rpm, in an acid formulation, andperiodically sampling the solution. The samples were then analyzed forthe calcium concentration as a function of time, which gives the rateconstant of calcite (CaCO₃) dissolution by hydrochloric acid containingsolutions. A decrease in rate constant indicates an acid retarding agentformulation whose surface reaction is retarded relative to hydrochloricacid alone, without any retarding agent. The plot in FIG. 5 illustratesslower dissolution rate, or slower rate of Ca²⁺ ions liberation overtime, for the 15% HCl solution containing MgCl₂ compared with unmodified15% HCl within 10 minutes. The results in FIG. 5 are a comparison of 15%HCl alone to 15% HCl mixed with 18.7% MgCl₂ retarding agent.

Example 3

Viscoelastic diverting acids (VDAs) consists of two main components: aviscoelastic surfactant) and hydrochloric acid. The viscosity of VDAsignificantly increases when the acid starts reacting with the carbonatereservoir (that is, when the pH increases)—this is due at least in partto the molecules of the viscoelastic surfactant rearranging to worm-likemicelles and forming a gel structure.

For this example, the fresh VDA included 36 v/v HCl (37 wt % solution),49 v/v MgCl2 (35 wt % solution), 5% v/v alcohol-containing solvent, 1.6%v/v corrosion inhibitor, and 7.9% v/v viscoelastic surfactant (39 wt %active component). The VES used was erucic amidopropyl dimethyl betaine.The rheology of “fresh” VDA (full HCl capacity) and “spent” VDA (nullHCl capacity) are measured at ambient temperature with a Fann 35viscometer and compared with VDA fluid which doesn't contain MgCl2 saltin the composition. Spent VDA was obtained by fully neutralizing the HClwith a sufficient amount of calcium carbonate powder.

As shown in FIG. 6 , the viscosity of the “fresh” VDA containingmagnesium chloride was about one order of magnitude lower than the“fresh” VDA which did not have magnesium chloride. Thus, addition of theretarder to VDA reduces friction losses when the fluid is pumped.

As shown in FIG. 7 , spent VDA containing magnesium chloridedemonstrates higher viscosity than spent VDA without magnesium chloride.Thus, the presence of magnesium chloride could possibly improvediversion properties of VDA.

Mechanistically, it is thought that magnesium chloride and urea can eachseparately disrupt the hydrogen bond network of water that free protonsdiffuse through to reach the surface of the porous media of theformation. This slows the diffusion of the acid. Furthermore, it isknown that magnesium chloride can lower the dielectric constant ofwater. Acids tend to have lower dissociation constants in lowerdielectric media. The activity of the proton could be lowered in thisway by forcing it to associate with its counteranion.

Example 4

Core flooding experiments with modified VDA (as described in Example 3)were conducted using Indiana limestone cores with permeability of 70 mDand porosity of 17%. Each core had a 6″ length and 1″ diameter. Thecores were saturated with 2% KCl brine prior to the test. The testtemperature was 200° F. VDA is injected at a constant rate into the coreuntil it broke through the other end of the core (PVBT). The injectionrate of VDA was varied in range of 0.1-6 ml/min. Dependence of PVBT onacid injection rate is shown in FIG. 8 .

As one can see in FIG. 8 , the addition of magnesium chloride makes VDAmore efficient (less fluid is required to break through the core). Inparticular, better efficiency of modified VDA is observed at lowinjection rates (below 6 ml/min). As shown in FIG. 9 , the wormholepattern also changes when the retarding agent (magnesium chloride) ispresent in VDA. The wormhole gets thinner and less core surface isdissolved with VDA containing magnesium chloride.

Example 5

VDA forms a viscous gel while penetrating the core and reacting withlimestone. The viscous gel creates resistance for fluid to flow throughthe core and the injection pressure builds up. Diversion ability of VDAcan be determined as a maximum pressure achieved in core floodingexperiments before the fluid breaks through (dP_(max)/dP₀, where dP₀ isbrine permeability).

In FIG. 10 one can see the pressure build-up when original VDA and VDAmodified with magnesium chloride (as described in Example 3) are pumpedthrough the core. In fact, the addition of magnesium chloride to VDAgenerates slightly higher pressure to flow through the core at the sameinjection rate.

Example 6

By fitting the pressure build-up data and PVBT data with new updatedcorrelations, we applied our in-house acidizing simulator for somesimple examples to show the benefit of VDA with MgCl₂. The simulatorused herein to provide the following simulation results is described inthe following reference and patents which are each incorporated hereinby reference in their entireties:

-   P. M. J Tardy, B. Lecerf, Y. Christanti-   “An Experimentally Validated Wormhole Model for Self-Diverting and    Conventional Acids in Carbonate Rocks Under Radial Flow Conditions”,    paper SPE 107854, presented at the European Formation Damage    Conference held in Scheveningen, The Netherlands, 30 May-1 Jun.    2007.-   P. M. J Tardy-   METHOD FOR PREDICTING ACID PLACEMENT IN CARBONATE RESERVOIRS; U.S.    Pat. No. 7,603,261, filed in the U.S. Patent Office on Nov. 29,    2006, granted Oct. 13, 2009.-   P. M. J. Tardy, B. Lecerf-   FLOW OF SELF-DIVERTING ACIDS IN CARBONATE CONTAINING HYDROCARBON    RESERVOIRS; U.S. Pat. No. 7,774,183 filed in the U.S. Patent Office    on Jul. 11, 2006, granted on Aug. 10, 2010

This example has two layers with different permeability contrasts,varying from 100 md/1 md, 100 md/10 md, 100 md/20 md up to 100 md/50 md.For each of these permeability contrasts, different injection rates areapplied, varying from 0.5 bbl/min, 1 bbl/min, 5 bbl/min up to 10bbl/min. With the same volume of 500 gal VDA or VDA/MgCl₂ pumped intothe formation, results of rate per zone and wormhole length are plottedto compare VDA/MgCl2 to original VDA. The data input for the example canbe found in Table. 1. The data input to the model also included thecomposition of the fluids prepared for Examples 3 and 4, and the PVBTdata from FIG. 8 and the pressure drop data from FIG. 10 for such fluidswas also used in the model.

TABLE 1 Input Data Zone 1 Zone 2 Thickness, ft. 50 50 Perm, md 100 1-50Porosity 15 15 Zone Pressure, psi 3206 3206

The simulation results are summarized from FIGS. 11 to 42 .

From the simulation results, one can conclude that for all the casesrun, VDA/MgCl₂ is showing a deeper wormhole penetration than originalVDA due to the better retardation factor. In addition, when permeabilitycontrast reduced to 10 or smaller, and rate increased to 1 bbl/min andabove, diversion starts to affect the flow rate distribution between thetwo zones. Based on the simulation results, the VDA/MgCl₂ is showing abetter diversion effect, due to the different pressure buildup behaviorof these two fluids.

The foregoing description of the embodiments has been provided forpurposes of illustration and description. Example embodiments areprovided so that this disclosure will be sufficiently thorough, and willconvey the scope to those who are skilled in the art. Numerous specificdetails are set forth such as examples of specific components, devices,and methods, to provide a thorough understanding of embodiments of thedisclosure, but are not intended to be exhaustive or to limit thedisclosure. It will be appreciated that it is within the scope of thedisclosure that individual elements or features of a particularembodiment are generally not limited to that particular embodiment, but,where applicable, are interchangeable and can be used in a selectedembodiment, even if not specifically shown or described. The same mayalso be varied in many ways. Such variations are not to be regarded as adeparture from the disclosure, and all such modifications are intendedto be included within the scope of the disclosure.

Also, in some example embodiments, well-known processes, well-knowndevice structures, and well-known technologies are not described indetail. Further, it will be readily apparent to those of skill in theart that in the design, manufacture, and operation of apparatus toachieve that described in the disclosure, variations in apparatusdesign, construction, condition, erosion of components, gaps betweencomponents may present, for example.

Although the terms first, second, third, etc. may be used herein todescribe various elements, components, regions, layers and/or sections,these elements, components, regions, layers and/or sections should notbe limited by these terms. These terms may be only used to distinguishone element, component, region, layer or section from another region,layer or section. Terms such as “first,” “second,” and other numericalterms when used herein do not imply a sequence or order unless clearlyindicated by the context. Thus, a first element, component, region,layer or section discussed below could be termed a second element,component, region, layer or section without departing from the teachingsof the example embodiments.

Although a few embodiments of the disclosure have been described indetail above, those of ordinary skill in the art will readily appreciatethat many modifications are possible without materially departing fromthe teachings of this disclosure. Accordingly, such modifications areintended to be included within the scope of this disclosure as definedin the claims.

What is claimed is:
 1. An aqueous composition, comprising: water; aviscoelastic diverting acid comprising hydrochloric acid (HCl) and azwitterionic viscoelastic surfactant (VES); a non-surface active,substituted ammonium containing amino acid derivative corrosioninhibitor; and a water-soluble acid retarding agent comprising at leastone salt compound and urea or a urea derivative, wherein the retardingagent is present in the aqueous composition in an amount between about 1and about 40 weight percent based on a total weight of the aqueouscomposition, wherein the zwitterionic viscoelastic surfactant has astructure in accordance with Formula III:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 17 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or alkylgroup having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl grouphaving from 1 to about 5 carbon atoms; and Y is an electron withdrawinggroup.
 2. The aqueous composition of claim 1, wherein the salt compoundcomprises: i) a cation selected from the group consisting of lithium,sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium,strontium, barium, scandium, yttrium, titanium, zirconium, hafnium,vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese,technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium,nickel, palladium, platinum, copper, silver, gold, zinc, cadmium,mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium,alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium,and combinations thereof; and ii) an anion selected from the groupconsisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate,sulfite, bisulfate nitrate, alkanesulfonates, arylsulfonates, acetate,formate, and combinations thereof.
 3. The aqueous composition of claim1, wherein the zwitterionic viscoelastic surfactant is erucicamidopropyl dimethyl betaine.
 4. The aqueous composition of claim 1,wherein the aqueous composition is in the form of a gel.
 5. The aqueouscomposition of claim 4, having a lower viscosity at a pH below about 0as compared to a viscosity of an equivalent aqueous composition whichdoes not contain the water-soluble acid retarding agent.
 6. The aqueouscomposition of claim 1, having a viscosity, at temperatures betweenabout 70° F. to about 200° F. and a pH above about 3, which is higherthan the viscosity of an equivalent aqueous composition which does notcontain the water-soluble acid retarding agent.
 7. The aqueouscomposition of claim 1, wherein the water-soluble acid retarding agentcomprises magnesium chloride (MgCl₂).
 8. The composition of claim 1,wherein the HCl is present in the aqueous composition at a weightfraction of at least 37%.
 9. A method, comprising: dissolving awater-soluble acid retarding agent comprising at least one salt compoundand urea or a urea derivative in an amount between about 1 weightpercent and about 40 weight percent in water to form a mixture;concurrently, or subsequently, adding to the mixture a viscoelasticdiverting acid comprising hydrochloric acid (HCl) and a zwitterionicviscoelastic surfactant (VES) to form an aqueous composition; andtreating a formation traversed by a wellbore with the aqueouscomposition, wherein the zwitterionic viscoelastic surfactant has astructure in accordance with Formula III:

in which R₁ is a hydrocarbyl group that may be branched or straightchained, aromatic, aliphatic or olefinic and contains from about 17 toabout 26 carbon atoms and may include an amine; R₂ is hydrogen or alkylgroup having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl grouphaving from 1 to about 5 carbon atoms; and Y is an electron withdrawinggroup.
 10. The method of claim 9, wherein the salt compound comprises:i) a cation selected from the group consisting of lithium, sodium,potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium,barium, scandium, yttrium, titanium, zirconium, hafnium, vanadium,niobium, tantalum, chromium, molybdenum, tungsten, manganese,technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium,nickel, palladium, platinum, copper, silver, gold, zinc, cadmium,mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium,alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium,and ii) an anion selected from the group consisting of fluoride,chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfatenitrate, alkanesulfonates, arylsulfonates, acetate, formate, andcombinations thereof.
 11. The method of claim 9, wherein thezwitterionic viscoelastic surfactant is erucic amidopropyl dimethylbetaine.
 12. The method of claim 9, wherein the aqueous composition isin the form of a gel.
 13. The method of claim 9, wherein the aqueouscomposition has a lower viscosity at a pH below about 0 as compared to aviscosity of an equivalent aqueous composition which does not containthe water-soluble acid retarding agent.
 14. The method of claim 9,wherein the aqueous composition has a viscosity, at temperatures betweenabout 70° F. to about 200° F. and a pH above about 3, which is higherthan the viscosity of an equivalent aqueous composition which does notcontain the water-soluble acid retarding agent.
 15. The method of claim9, wherein the water-soluble acid retarding agent comprises magnesiumchloride (MgCl₂).
 16. The method of claim 9, further comprising addingto the mixture a non-surface active substituted ammonium containingamino acid derivative corrosion inhibitor.
 17. The method of claim 9,wherein the HCl is added in a weight percentage up to 45.7%.